Horizontal wellbore pump system and method

ABSTRACT

A pump system and method for producing fluids from a reservoir using a wellbore having a vertical section with a casing defining a wellbore annulus, a horizontal section in fluid communication with the wellbore annulus, and a production tubing having a vertical section, a horizontal section and a toe end, the production tubing defining a continuous flow path from the toe end to the vertical section, the system comprising a plurality of horizontal pump assemblies operating in parallel in the production tubing horizontal section. Each horizontal pump assembly includes a pump having an intake exposed to the reservoir and an outlet in the continuous flow path, and a fluidseeker which has an inner conduit forming the continuous flow path and defining an inlet chamber, and including an axially rotatable inlet extension disposed in the inlet chamber. The inlet extension has a weighted keel defining inlet ports which are in fluid communication with the inlet chamber and a fluid inlet for the pump.

FIELD OF THE INVENTION

This application relates to horizontal and vertical well fluid pumpingsystems and methods which mitigate heel preferential depletion andstranded reserves in the horizontal section.

BACKGROUND

It is well known in the art of oil and gas production to use pumpslanded in the deepest point of a vertically oriented wellbore, or at theheel of the horizontal wellbore, to lift produced liquids from thereservoir to surface. Traditional vertical artificial lift solutions arewell known. Various mechanical pumps such as rod pumps, progressivecavity pumps, electric submersible pumps or hydraulically actuated pumpsare in widespread use in the oil and gas industry.

There are many benefits to utilizing a horizontal drilling andcompletions strategy for completing and producing wellbores. Ahorizontal wellbore can increase the exposure of the reservoir bycreating a hole which follows the reservoir thickness. A typicalhorizontal wellbore plan also allows for the wellbore trajectory totransversely intersect the natural fracture planes of the reservoir andthereby increase the efficiency of fracture stimulation and proppantplacement and therefore total productivity.

The primary advantage of a horizontally oriented wellbore is theexposure of a greater segment of the reservoir to the wellbore using asingle vertical parent borehole than is possible using several verticalwellbores drilled into the same reservoir. However, in order to maximizethis advantage, well performance must be proportional to the exposedlength of reservoir in the producing well. As is commonly known in theindustry, the relationship of well exposure to well productivity is notdirectly proportional in horizontal wellbores.

Generally, the production of horizontal wellbores is initially exploitedusing reservoir energy. The vast majority of horizontal wellbores arenow stimulated using horizontal multi-stage fracturing systems toincrease the exposure of the reservoir to the horizontally orientedwellbore. However, this stimulation technique only finitely energizesthe reservoir, with the pressure returning quickly to the originalin-situ reservoir pressure. If the reservoir drive is insufficient orquickly dwindles, production from the horizontal segment of the wellboreis drawn down utilizing a single pump inlet landed at or near the heelof the horizontal wellbore. Alternately, other conventionally known liftsolutions such as plunger lift and gas lift are used to manage the backpressure on the formation through the vertical and transitional sectionof the wellbore. Other services such as jet pumps are used in anintermittent capacity to unload or clean out the horizontal wellboresection.

Conventional means for producing a horizontal well do not influence thereservoir much past the heel of the wellbore, resulting inheel-preferential depletion where drawdown is localized to the region inthe heel.

The drawdown pressure is also limited to the theoretical vapor pressureof the fluid being pumped. A producing oil well, either horizontal orvertical, transitions through its bubble point during its producinglife. When this occurs, gas escapes from solution and there exists atleast two separate phases (gas and oil) in the reservoir, resulting in agas cap drive. The efficient production of these types of reservoirs isaccomplished by carefully managing the depletion of the gas cap drive,which may be monitored by the produced gas/liquid ratios. In atraditional free-flowing gas cap drive well, fluids will be mobilized bythe gas drive and follow the path of least resistance in the journeytowards the surface. Again, this results in a disproportionateproduction of the reservoir in the vicinity of the heel of the wellbore.The onset of premature depletion at the heel is exacerbated by thesingle drawdown location in the wellbore located near the heel. Thisproduction regime is present throughout the producing life until such atime as the heel becomes depleted and the gas cap drive breaks throughnear the heel. Gas cap drive breakthrough will result in elevatedgas/liquid ratios. This can result in gas locking and fluid pounding,overheating, fluctuating torques, increased pump slippage(plunger/barrel or rotor/stator) and lower pumping efficiency, which canlead to significant damage to the vertical pumping solution. Eventuallythe gas drive will deplete, leaving unproduced fluid (reserves) in thereservoir space, thus leading to low recovery factors and stranded oilin the reservoir.

The concept of preferential depletion of substantially horizontalportions of subterranean wellbores has become more commonly known withinthe energy industry. The drilling, completion and production practicesemployed to date have resulted in reserves being trapped deeper in thesubstantially horizontal portion of these subject wellbores andconsequently the expected producing life of these assets is shorter thanwas originally proposed and therefore the assets become lesseconomically viable. Particularly in the case of solution gas drive typereservoir, the preferential depletion leads to a premature depletion ofthe available drive energy to support the production of the reserves.Coupled with mixed phase flow in the wellbore, the gas phase flows mostreadily, thereby leaving saleable liquids behind. This conditionmanifests as a well which ultimately behaves very differently along itslength and therefore produces different results.

The preferential depletion of the heel portion of a horizontal wellboresegment creates a production scenario in which the horizontal section ofthe wellbore behaves as if it were two distinct wells. One potentialsolution involves multiple pumps spaced apart in the horizontal section.If the production is isolated from the reservoir, except through thehorizontal pumps, each horizontal pump may be controlled to managedrawdown in different zones of the horizontal section.

Producers are experiencing primarily gas production near the heel of awellbore with progressively more fluid production deeper into thehorizontal section of the wellbore. They are seeing the presence ofdrill cuttings on pumping system components located near the toe of thewellbore upon retrieval to surface, which indicates little to no flowfrom this region of the wellbore from the original drilling and fracturestimulation. They are seeing elevated water cuts (up to 100%) in regionswhere the in-situ water cut for a normal reservoir is only 5-10%, whichsuggests that fracture stimulation fluid remains trapped the reservoirfrom the original completion and stimulation practices. Evidence offracture stimulation chemicals in retrieved fluid samples from thehorizontal pumps deployed into the test wellbore, segregation of regionsof the horizontal wellbore segment from one another, limiting cross-flowcommunication along the horizontal segment despite there being clearfluid communication between said regions, are all symptoms ofinefficient pumping along the horizontal section. There also appears tobe rapid fluid separation between oil, water and gas phases, resultingin a “treater” style flow regime along the horizontal, leading to waterquickly accumulating in the dip traps, potentially shutting offproductivity from deeper in the horizontal wellbore.

Although very little testing or logging in the horizontal wellboresegments is being currently done following fracture stimulation andbefore the well is placed on production, the limited testing which isbeing done is proving through instrumentation and spinner surveys thatmoving beyond the first wellbore trap created by the varying elevationsalong the horizontal during the drilling program results in a cessationof reservoir productivity beyond this trap.

There remains a need in the art for artificial lift systems including ahorizontal pumping system designed to address lifting efficiencies alongthe entire wellbore length irrespective of the state of depletionevident in a particular region of the substantially horizontal wellboresegment.

This background information is provided for the purpose of making knowninformation believed by the applicant to be of possible relevance to thepresent invention. No admission is necessarily intended, nor should beconstrued, that any of the preceding information constitutes prior artagainst the present invention.

SUMMARY OF THE INVENTION

In general terms, the invention comprises a pumping system integral tothe horizontal tubing string which comprises horizontal pumps,directional flow devices positioned between the horizontal pumps, andconfigured to prevent the individual pump discharges from interferingwith one another, and to improve the quality of the fluids being pickedup by the horizontal pumps. In effect, each of the horizontal pumps areisolated from each other, such that they act in parallel, independentlycontributing to a central flow passage in the production tubing.

In one aspect the invention may comprise a pumping system integral to aproduction tubing in a horizontal section of the wellbore, comprising aplurality of horizontal pumps, wherein each horizontal pump isassociated with a directional flow control device and a fluidseekerconfigured to preferentially direct liquids into the horizontal pumpintake. Preferably, each horizontal pump is also associated with atubing drain integral to the tubing. The flow control device is intendedto direct the pump discharge from each horizontal pump, which operatesindependently of other horizontal pumps, into the production tubingstring and toward the heel of the well, which will prevent the pumpdischarge from interfering with the fluids discharged from the adjacentpump immediately downhole. Thus, each pumping segment is effectivelyisolated and independent of the others. In order to facilitateretrieval, the tubing drain is collocated with each directional flowcontrol device, allowing fluid in the production tubing to drain fromwithin the tubing string during a pumping system retrieval.

In another aspect, the invention comprises a method of producing fluidsfrom a horizontal section of a wellbore, having a heel segment and a toesegment, comprising the steps of:

(a) landing a production tubing having a plurality of integratedhorizontal pumps into the horizontal wellbore, the tubing defining (i) acentral fluid passage which is continuous from a toe end to the heel endand (ii) an annulus between the tubing and a liner or reservoir face;wherein each horizontal pump has an intake located in a lower portion ofthe annulus and an outlet discharging into the central fluid passage;wherein the central fluid passage is closed to the reservoir exceptthrough a pump outlet, wherein one or both of the pump intake and outletcomprises a one-way valve; and wherein the central fluid passagecomprises a directional flow control device disposed between adjacenthorizontal pumps; and

(b) independently operating each horizontal pump to pump liquids intothe central fluid passage, while leaving gases in the annulus.

BRIEF DESCRIPTION OF THE DRAWINGS

In the drawings, like elements are assigned like reference numerals. Thedrawings are not necessarily to scale, with the emphasis instead placedupon the principles of the present invention. Additionally, each of theembodiments depicted are but one of a number of possible arrangementsutilizing the fundamental concepts of the present invention. Thedrawings are briefly described as follows:

FIG. 1A shows an undepleted substantially horizontal wellbore, with aconventional artificial lift device installed near the bottom of thevertical section of the well. FIG. 1B shows the same wellbore, withdepletion near the heel portion of the horizontal section.

FIG. 2 shows a schematic representation of a horizontal wellbore,showing the pumping system comprising directional flow devices and pumpswith fluidseekers, deployed along the length of the horizontalproduction tubing.

FIG. 3 shows a cross-sectional schematic of a wellbore showing a highangle artificial lift pump connected to a heel portion fluid seeker andseparation system.

FIG. 4 shows a detailed view of one embodiment of a directional flowcontrol device.

FIG. 5 shows a schematic of a pump assembly of one embodiment of thepresent invention.

FIG. 6 shows a longitudinal cross-section of a pump intake fluidseekerassembly.

FIGS. 6A-6F show transverse cross-sections along the lines indicated inFIG. 6.

FIG. 7A shows a schematic isometric, transparent view of a pump intakefluidseeker assembly. FIG. 7B shows a cross-sectional isometric view ofFIG. 7A.

FIGS. 8A-8F each show an enlarged portion of FIG. 5.

FIG. 9A shows a longitudinal cross section of the releasable, rotatablesealed tubing clutch in the fully locked state in which state thepumping/production operations may commence.

FIG. 9B shows a longitudinal outer view of FIG. 9A, from which the lockhousing has been removed in order to show the castellations between theindexing mandrel and clutch in the locked condition. Which castellationshave the principal purpose of preventing rotation between the same.

FIG. 9C shows a longitudinal outer side view of the same clutch assemblyin the locked state but wherein the locking housing is threadinglydis-engaged from the clutch body thereby exposing the LH detent ring andthe clutch body thread.

FIG. 9D shows a longitudinal cross section of the clutch assembly in thefully disengaged operable to permit rotation of the pump assembly withrespect to the fixed tubing element threadingly engaged with the clutchbody.

FIG. 9E shows the same clutch positional assembly from FIG. 9D but withthe lock housing removed thereby exposing the castellations in theirfully disengaged position.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

The invention relates to a pump method and system for a horizontalwellbore. The present invention builds on the general configuration andconcept of the system and method described in Applicant's co-owned U.S.Pat. No. 9,863,414, entitled Horizontal and Vertical Well Fluid PumpingSystem”, the entire contents of which application are incorporatedherein by reference, where permitted. When describing the presentinvention, all terms not defined herein have their common art-recognizedmeanings. To the extent that the following description is of a specificembodiment or a particular use of the invention, it is intended to beillustrative only and not limiting of the claimed invention.

Embodiments of the present invention are described in the context of awellbore having a vertical section, a horizontal section and anintermediate build section, as schematically depicted in FIGS. 1A and1B. Systems of the present invention may combine with a artificial liftdevice, such as a high-angle reciprocating rod pump. In someembodiments, the high-angle rod pump may be landed just below the buildsection, in the heel of the horizontal section.

As used herein, the terms “distal”, “downhole”, “proximal” and “uphole”are used to describe the relative positioning of elements relative tosurface equipment, where the distal end of components is fartherdownhole, away from the surface, while the proximal end is uphole,closer to the surface, regardless of the actual relative vertical orhorizontal position of the components.

The horizontal section of the wellbore may comprise a build segmentwhere the inclination transitions from the kick-off point to fullyhorizontal orientation, followed by a heel segment which includes thefirst set of fractured perforations, in other words the beginning of theproducing interval in the horizontal section, and terminates with thetheoretical boundary of preferential depletion; and a toe segmenttransitioning through the non-depleted interval and terminating at thetoe end of the horizontal wellbore section. There may be a plurality ofsegments throughout the horizontal section, intermediate the heelsegment and toe segment. In some embodiments, each segment comprises atleast one pump assembly, as described below.

Each segment may coincide with naturally occurring features of thereservoir, such as impermeable features, represented by the darker areasshown in FIG. 2. However, there is no annular isolation between thesegments, and fluids may flow along the annulus between the productiontubing (10) and the liner (12) along the entire length of the horizontalsection. As discussed below, the system is configured to encourage gasflow along the annulus, towards the heel segment and the build section.

As shown schematically in FIG. 2, the system comprises a productiontubing string (10), which runs the length of the horizontal section fromthe toe end (14) to the build section (16). The production tubing may beinstalled within a slotted liner (12), as is well known in the art.Reservoir fluids enter the wellbore, through the liner (12), where thefluids may be picked up by the pumping system. At least one, andpreferably a plurality of horizontal pumps (18) are placed along theproduction tubing string, each pump having an intake (20) facing thereservoir, and discharges into the production tubing string. In someembodiments, the horizontal portion of the production tubing string isisolated from the reservoir, except through the horizontal pump intakes.

In one embodiment, as shown in FIG. 3, the vertical lift pump (30) islanded in the build section, and comprises a high angle rod pump, whichoperates in a conventional manner, but may include adaptations whichpermit its use at more horizontal orientations, and even completelyhorizontal. Examples of such a pump are described in co-owned U.S.patent application Ser. No. 15/321,140 entitled “Rod Pump System”, theentire contents of which are incorporated herein by reference, wherepermitted.

In some embodiments, the vertical lift pump (30) may combine with afluid flow management system (40) for treating a multi-phase fluidstream, such as that described in Applicant's co-pending PatentCooperation Treaty application filed on Mar. 12, 2019 and entitled“Horizontal Wellbore Separation System and Method”, the entire contentsof which are incorporated herein by reference, where permitted.Generally, the fluid flow management system is configured to passthrough high quality liquid flow being pumped from downhole segments ofthe horizontal section to the vertical lift pump intake, and de-energizedisorganized mixed phase flow in the annulus, allowing for accumulationand pickup of liquids, while allowing gas flow to continue through theannulus.

In some embodiments, the fluid flow management system comprises:

(a) a central flow passage (50) which receives production fluid flowfrom the downhole segments of the horizontal section, and is continuousto the toe end of the system;

(b) a slug mitigation device or wavebreaker (42) disposed in the annulusexternal the production tubing, adjacent to and proximally located froma centralizer device, which wavebreaker encourages well liquids toaccumulate in the lower portion of the annulus, while permitting gasflow to continue around the wavebreaker;

(c) optionally, at least one baffle plate for normalizing the flowconditions of multi-phase stream, leading to phase separation;

(d) an inline fluidseeker (44), which self-orients downwards by gravity,increasing the likelihood that the fluidseeker intake (46) will beimmersed in liquids in the lower portion of the annulus.

In preferred embodiments, mixed phases accumulate in the annulus upholefrom the fluidseeker (44), which annulus may be considered to be aseparation chamber. As the mixed phases are retained in this separationchamber, liquids which condense or coalesce in this section drop to thebottom of the chamber, where the fluidseeker inlet (46) is disposed. Asection of pipe in this separation chamber may comprise at least oneperforated pipe interval configured to allow gases to escape to theannulus, while having an inner tube forming the central fluid passage(50), which takes high quality liquid flow to vertical pump intake.

The horizontal pumping system may now be described, starting at the toeend of the system. A plug (52) caps and seals the toe end of theproduction tubing, isolating the central fluid passage (50) from thereservoir, except though the horizontal pumps. At spaced intervals alongthe central fluid passage (50), directional flow devices (60) comprisingone-way valves are inserted into the flow, ensuring that produced fluidsdo not backup into a downhole segment, but rather progress upholetowards the heel and the artificial lift device to be transported to thesurface. The horizontal pumps (18) with downward facing inlets (20) areintegrally placed in the production tubing.

One embodiment of a one-way valve (60) is shown in FIG. 4 and isconfigured to be inserted between conventional tubing joints. Aconnecting sub (62) threads onto and connects between the threaded endsof the tubing joints. A reciprocating valve (64) is biased by a spring(65) into a closed position seated against the valve seat, with upperand lower shafts (66) retained by slotted discs (68) which permit fluidflow when the valve (64) is lifted off the valve seat.

A pump assembly (70) is shown in longitudinal cross-section in FIG. 5with a number of transverse cross-sections. The assembly comprises of anintake section (72), a fluidseeker section (100), and a pump section(200). At its downhole end, the pump assembly (70) has a clamp adapter(80) which forms part of the tubing string, and serves to externallycarry electrical connectors (98) and capillary lines (99) which arerequired at least for data transmission, pump activation and control.The electrical connectors and capillary lines run virtually the entirelength of the system, and must therefore pass through components or becarried on the exterior of components of the system.

Clutch Assembly

A clutch assembly (90) is required in the context of deploying downholedevices, or downhole horizontal pumps along the wellbore with commonactivation strings (99) whether it be capillary lines for a fluid systemor electrical lines for an electrically powered pumping system orsmaller gauge wire for instrumentation systems and data collection. Allof these variations have a common foundational challenge involved inconsistently and reliably making connections with the external lines ateach of the deployable device locations. Where the tubing string is madeup with a specified connection torque and not an aligned rotationalposition, the angular position of the capillary lines (99) with respectto the tubing below the pump and the rotational position of the linesexiting the local pump may not necessarily be in alignment. Therefore,in some embodiments, a rotatable and sealed tubing deployed clutch (14)allows for installation of multiple pump deployments with capillarylines and electrical conduits.

In such conditions the rotatable, sealed tubing deployed clutch permitsconditions whereby the tubing and operational device may be temporarilydisconnected in a rotatable sense to allow the external activationconduits to be aligned with the same in the device. Then the clutch maybe re-engaged and locked and the subsequent operations continued.

In some embodiments, the rotatable, sealed tubing deployed clutch iscomprised of an indexing mandrel (90) disposed within and sealinglyenagaged with the clutch body (91). The mandrel and the clutch body areaffixed to one another in a rotational sense with the engagement of thecastellations (92) located on the outer surface of the indexing mandreland on the proximal end face of the clutch body. The engagement of thecastellations is controllable by the axial position of the lock housing(93), surrounding the castellations (92) disposed between the twobodies.

In the fully locked position, as shown in FIG. 9A, externally appliedtorque is transmitted by the castellations (92) between the indexingmandrel (90) and the clutch body (91). FIG. 9B shows the locked state,where the lock housing (93) is removed for visualization purposes only,showing the castellations (92). In the same manner externally appliedtension is transmitted through the device by way of the locking segments(94) disposed radially between the outer surface of the indexing mandreland the distal end face of the lock body and finally through theinternal threads of the lock body which are threadingly engaged andspanning the castellations between the lock body external threads andthe clutch body external threads.

FIG. 9C shows the clutch where the lock housing (93) has beendisengaged, but with the castellations (92) still engaged. The mandreland the clutch body may then be pulled apart, disengaging thecastellations, as shown in FIGS. 9D and 9E. In this disengaged state,the mandrel and clutch may be freely rotated relative to each other, inorder to align the capillary lines and electrical lines.

Reliable re-engagement of the castellations after the new rotationalposition has been established is accomplished by way of the indexingalignment slots (95). The slots are transversely aligned with the malecastellations of the clutch body and the corresponding femalecastellations on the indexing mandrel. Therefore, with the castellationsbeing enclosed by the lock housing during normal operations there-alignment and re-engagement of the castellations is accomplished byvisually and/or physically aligning the indexing alignment slots on thedistal and proximal ends of the clutch assembly. Once said slots are inaxial alignment, the clutch assembly may be closed and locked in thereverse operation which caused the castellations to be dis-engagedinitially.

Sealing engagement of the two main bodies is permitted by the sealassembly (96) radially disposed on the outer surface at the distal endof the indexing mandrel. Sealing engagement and seal movement is limitedby way of the limit detent ring (97) expanding into the pre-disposedinternal groove of the clutch body as the indexing mandrel is permittedto travel towards the proximal end of the same.

Intake Section

The intake section (72) comprises a bottom bulkhead (73), and inner tube(74) which is a continuation of the central flow passage (50) of thesystem, and outer filter tube (75) which acts as the intake filter.Production fluids pass through the outer filter tube (75) whileexcluding unwanted solids (sand etc.). Cross-section B-B is taken at theuphole end of the intake filter and the start of the fluidseeker section(100).

Fluidseeker

As shown in FIG. 5 and FIG. 6, the fluidseeker section (100) comprises afluidseeker central inner conduit (101) which is a continuation of thecentral fluid passage (50) of the system, but also defines an inletchamber (102) within which a rotatable inlet extension (103) having aweighted keel (104) is disposed, which provides a fluid inlet for theassociated pump.

The fluids in the annulus in the region of the intake section may bedisorganized with gas and liquid slugs. Generally, however, the liquidsin the annulus will of course settle to the lower section of theannulus. Thus, the fluidseeker (100) is configured to provide a fluidinlet in the lower section. Annular production fluids enter the fluidseeker in the passage between the outer housing (105) and the centralinner conduit (101). The inlet extension (103) is rotatably mounted withsuitable seals and bearings to the central inner conduit (101) with theweighted keel (104) defining inlet ports (106). The opposing sidecomprises a barrier (107) which is sealed to the central inner conduit(101) and the inner surface of the inlet block (107), all of whichdefines the inlet chamber (102).

As may be seen, liquids which enter the fluidseeker accumulate in thelower half of the intake chamber (102), where the weighted keel (104)inlet ports (106) allow passage to the uphole side of the rotatableinlet extension (103). Gases in the upper half do not progress past therotatable inlet extension barrier (107). Intake ports (109) in the inletblock (108) continue the fluid passage from the intake chamber (102) tothe primary pump intake chamber (110). The uphole end of the fluidseekerassembly shown in FIG. 5 then connects to the pump section (200) asdescribed below.

In some embodiments, the system may comprise intake float (not shown)disposed on the rotatable inlet extension within the fluidseeker intakechamber (102), with a level switch (not shown) operably connected to theactivation system (301). Because the rotatable inlet extension (103) isalways oriented vertically, the intake float may be configured toactivate the level switch to initiate pumping when the intake floatindicates a sufficient liquid level present int the inlet chamber,ensuring that the fluidseeker inlet extension ports (106) are immersedin liquid, and cease pumping when the level switch indicates that theliquid level has fallen below a specified operable lower limit. By themeans of the float, the pumping efficiency of the horizontal pump may bemanaged in such a way that the device may only be active when the intakeassembly is full of fluid.

Capillary line passages (99) are shown in the transverse cross-sectionsof the fluidseeker, as a number of capillary lines must pass through thefluidseeker.

Pump Section

A distal flow sub (201) connects to the uphole end of the fluidseekerassembly, and continues the central fluid passage (50), as may be seenin cross-sections J-J and K-K. The primary pump intake chamber (202)comprises a one-way valve (203), which leads to the pump intake annulus(204), shown in FIG. 5 and cross-section K-K. The horizontal pump (200)comprises an elongated diaphragm pump (205), such as a pump described inU.S. Pat. No. 9,863,414, shown in cross-section in L-L.

In preferred embodiments, the diaphragm pump (205) comprises aflow-through passage which is the continuation of the central fluidpassage (50), which flows through the pump (200) unimpeded. The pumpsection (200) comprises the distal flow sub (201) at the downhole endand a proximal flow sub (206) at the uphole end. The production chamber(207) of the pump is disposed between the internal mandrel (208) whichinternally defines the central fluid passage (50) and an expandablediaphragm (209) disposed between the outer housing (210) and the innermandrel (208).

In some embodiments, the inner mandrel (208) has a lobed transverseprofile (as seen in cross-section L-L) through a middle section. As aresult, the production chamber (207) primarily comprises of the spacebetween the lobes (210), of which there are four lobes in the embodimentshown. Activation fluid inlet passages (211) and exhaust passages (212)run axially through the lobes (210), and through ports in fluidcommunication with the activation chamber which is between the outerhousing and the diaphragm (209).

At the uphole end, the production chamber (207) leads to discharge ports(213) through the mandrel (207), which are in fluid communication withthe pump outlet and the discharge passage (214) in the proximal flow sub(206). The discharge passage (214) in the proximal flow sub (206)comprises a one-way valve (215). Thus, the diaphragm pump (205) usesone-way valves at the suction end and the discharge end to ensure properflow of the produced fluids. The pump discharge then merges with thecentral flow passage (50) in the proximal flow sub (206).

Because of the one-way valve assemblies, the pump output is isolatedfrom the central flow passage, which carries the cumulative output ofdownhole pump assemblies, except when the pump is active discharginginto the central flow passage.

A top bulkhead (300) houses the activation system (301) which receivesthe activation and exhaust capillary lines, electrical lines, andincludes the actuation valves necessary to control operation of thediaphragm pump. The bulkhead (300) then connects to a tubing adapter(400), which may then be connected to regular lengths of tubing (500)which separate the pump assembly (200) from the next uphole pumpassembly.

The electrical conduits (98) and capillary lines (99) continue along theentire tubing string, passing through system elements as required, andclamped externally to tubing and system elements as necessary. Theclutch assembly permits rotational makeup of the system, whilemaintaining axial alignment of the conduits and lines.

Efficient retrieval of the substantially horizontal multi-pumpartificial lift system requires the fluid within the continuous fluidpassage (50) must be drained as the tubing system is retrieved from thewell. With several directional control valves integral to the tubingwithin the wellbore completion, retrieval of the system from thewellbore requires that a means of draining the tubing is collocated witheach instance of the proposed directional control valve. This means isaccomplished by the installation of tubing drains or burst joints as arewell known in the art. When the tubing pressure inside the first fluidflow path is artificially elevated above the burst joint pressure, adrain opening is created such that fluid is permitted to pass into theannular space within the well casing, from within the tubing string.This ensures that the tubing internals are dry as the tubing is trippedtoward surface and prevents wet trips with tubing as each joint issurface during the system retrieval.

In some embodiments, a multi-phase flow measuring instrument may beprovided in one or more horizontal or vertical wellbore segments, whichmeasures, acquires and/or processes downhole information from selectedwellbore locations. This information may be used by an intelligentcontrol system to vary pump rates or operating states to optimizeproductivity along the length of the horizontal wellbore.

In some embodiments, the pumping system and method may be configured soas to avoid placing horizontal pumps in sections of the horizontalwellbore which are known to be depleted. For example, if the heelsegment and an adjacent segment have both been depleted, the high anglereciprocating rod pump and fluid flow management system may positionedmuch farther downhole than the heel of the wellbore.

In another aspect, the invention comprises a method of producing fluidsfrom a horizontal section of a wellbore. A system comprising aproduction tubing having a plurality of integrated horizontal pumps asdescribed herein, such as schematically illustrated in FIG. 2, is landedinto the horizontal wellbore. The tubing defines (i) a central fluidpassage (50) which is continuous from a toe end to the heel end and (ii)an annulus between the tubing and a liner or reservoir face. Eachhorizontal pump has an intake located in a lower portion of the annulusand an outlet discharging into the central fluid passage (50); whereinthe central fluid passage is closed to the reservoir except through eachhorizontal pump. One or preferably both of the pump intake and outletcomprises a one-way valve. The central fluid passage (50) comprisesdirectional flow control devices, such as one-way valves, which aredisposed between adjacent horizontal pumps. A control systemindependently operates each horizontal pump to pump liquids into thecentral fluid passage, while leaving gases in the annulus.

Gases and mixed-phase flow migrates in the annulus towards the heelsegment, where they encounter the fluid management system, whichencourages further phase separation. Gases continue to travel up theannulus, in the vertical section of the wellbore. Liquids are picked upby the fluidseeker inlets along the system, and delivered to the intakeof the vertical lift pump.

In preferred embodiments, the system further comprises a plurality ofsensors deployed in the different wellbore segments, which collect andtransmit data to a control system. The control system operates each ofthe horizontal pumps, either by turning the pump on or off, orincreasing or decreasing the pump rate, in response to the downholeconditions reported by the sensors. The sensors may include pressure,temperature, flow rate, fluid level, sensors or the like. Thus,embodiments of the invention include methods of data collection,assembly, presentation and subsequent research, preparation and analysisas situationally required in order to present an artificial lift systemdesign to systematically and orderly pump a substantially horizontalwellbore segment along the horizontal and thereby efficiently deliveringliquids to the intake of the operable high angle lift intake.

One aspect of the invention include methods of reviewing wellbore data,analyzing operating and reservoir conditions and presenting a systemdesign which is unique to a given wellbore and designed to present thebest potential results for the same. The desired result is to accesspreviously undrained reserves within the well reservoir by placing apumping system along the previously undrained reservoir section.

Therefore, in some embodiments, the method may comprise one or more ofthe following. Some or all relevant and pertinent data surrounding apotential wellbore application may be collected, which data may include:

(a) wellbore pressure/reservoir pressure (which may be ascertained byway of analog well sensors, historical data or by means of a down holepressure survey);

(b) wellbore temperature (which may be ascertained by way of analogwell, historical data or by means of a down hole temperature survey);

(c) wellbore directional survey data;

(d) historical production data: GOR, GLR, Water Cut, Oil Cut, WaterRate, Oil Rate, Gas Rate, etc, (ascertained either historically with thesubject wellbore or by way of an analog well or group thereof);

(e) annular liquid levels, preferably of the de-gassed (or depressedcolumn) as a means of estimating the available reservoir pressure;

(f) reservoir quality logs, such as gamma ray;

The data may be assembled or processed in a meaningful way so as toallow logical predictions as to the producing capability of the subjectreservoir. In some embodiments, the assembled data may be used:

(a) to inform the placement of each of the horizontal pumps along thesubstantially horizontal wellb ore segments;

(b) for comparison of the data against a database of known reservoirdata and performance and to select an analog which may inform the designof said pumping system and the pump placement within the same;

(c) in concert with empirically discovered pressure and friction lossdata to estimate the required pumping pressures along the length of thesubstantially horizontal wellbore segments;

(d) to inform the required surface pumping horsepower of the systemsdesign;

(e) to size the capillary tubing to match the required system pumpingrates;

(f) to size the electrical conduits designed to power the horizontalpumps strategically placed along the length of the substantiallyhorizontal wellbore;

(g) to size the tubing string required at each stage or segment of thesystem;

(h) to predict requirement of friction reducing lining disposedinternally to the production tubing, which tubing is in fluidiccommunication with the discharge portion of each horizontal pump;

(i) to predict the required pumping rate for the subjectwellbore/reservoir;

(j) combined with a method such as a material balance calculation as iswell known in the art to predict the remaining reserves in place and theexpected lifetime performance of said horizontal and vertical well fluidpumping system;

(k) to predict the well fluid pumping device or combination thereofwhich may be deployed into the subject wellbore, including withoutlimitation, a reciprocating rod pump, a diaphragm pump, an electricsubmersible pump, a hydraulic submersible pump, a jet pump, a pneumaticdrive pump, a gas lift pump, a gear pump, a progressive cavity pump, avane pump or combinations thereof;

(l) in combination with a predictive calculation tool such as:computational fluid dynamics, gas volume (void) fraction, OLGA flowmodelling software, or any other tool of the like, in order to predictflow conditions along the horizontal section, which flow conditions mayinform the placement of the pumps and their future performance or topredict the improvement to the net present value of the producing assetwith the horizontal and vertical well fluid pumping system beinginstalled and operable to pump the fluids along the substantiallyhorizontal wellbore segments towards the intake of the high angle liftsolution.

The methods of the present invention may be applied in conjunction withunconventional or enhanced recovery techniques, such as steam assistedgravity drainage, miscible flood, steam (continuous or cyclic), gas orwater injection.

Thus, in aspects of the invention, the horizontal pumping system may beschematically understood to have a first fluid path which is the centralflow passage (50) and a second flow path which is along the annulus,each of which paths are separate and differentiable in the wellbore. Thesystem, with each fluidseeker, takes a portion of the second fluid pathin the annulus which is primarily liquid and adds it to the first fluidpath by means of the horizontal pump. The remaining fluids in the secondflow path is transported to the heel segment, where continued separationprovides liquids to add to the first flow path, and remaining gasescontinue up the annulus.

The two paths remain distinct as they exchange dominance providingpreference to the dominant flow in time by way of the directional flowcontrol devices, valve which ensures advancement of the flow towards thehigh angle lift intake only. In some embodiments, production from apreferentially depleted horizontal segment is lifted using only the highangle lift solution located adjacent to the flow management andseparation system. Where mixed phase slugging flow exists in theannulus, initiating from a preferentially depleted heel wellboresegment, it is de-energized by the wavebreaker and then passes throughthe separation system, undergoing retention time and phase separation.This process properly conditions the fluids in order to present thehighest possible liquid quality to the high angle lift system intake.

Each horizontal pump adds higher quality liquid to the first fluid flowwhich eventually is directed into the high angle rod pump solution. Suchhigher quality liquid is a product of the phase separation taking placeat the fluidseeker intake of the at least one horizontal pump. The firstfluid path flow is controlled passively by the dominant fluid, where thefirst and second fluid paths exchange dominance in time, influenced bythe discretely differentiable pressure conditions in the source rockreservoir.

As the flow in the annular space (second fluid flow path) becomesdominant over the flow first fluid flow path, the weighted keel intakeof the fluidseeker assembly permits flow into the high angle liftsolution intake from the preferentially depleted region of the subjectwellbore. This configuration permits an unbiased drainage of the entirewellbore despite the depletions status of any particular region, by wayof the high angle lifting solution.

In a wellbore which has substantially horizontal segments which aresubstantially undepleted in nature, the condition of the fluid and thebehavior of the reservoir along the wellbore length may behavesimilarly, therefore this well may behave as a single congruent entity.In this condition, the wellbore is configured with at least onehorizontal pump whose discharge is directed to along the first flow pathto the high angle lift solution intake. In this case, there is littleflow in the second fluid path.

The weighted keel configuration of the fluidseeker tends to mobilize themost readily mobile fluid medium preferentially toward the pump systemintake.

The nature of the multi-flow in the substantially horizontal wellboresegments tends to be unorderly and disorganized in nature. This type offlow can be expected in the fluid flow path one and in the annularregion between well casing ID and OD of the tubing which surrounds thecentral fluid passage (first fluid path). The changing elevations,pressures and proportions of each fluid phase along the horizontal allcontribute to disorganized, intermittent and unpredictable flow regimesand production results. An additional layer of complexity is presentwhen inside the tubing which surrounds the central fluid passage sincethe tubing is isolated everywhere along its length except at the intakethrough each horizontal pump. When pumping multi-phase liquids with atleast one horizontal pump the fluid conditions on the discharge side ofthe horizontal pumps may also include gasses which introducecompressibility into the first fluid flow path from its distal end atthe discharge of the at least one horizontal pump to the proximal end atthe inlet to the fluidseeker, or adjacent to and in fluidiccommunication with the intake to the vertical pumping solution.

With no biasing means present along the first fluid flow path, thepressure elevation introduced by the at least one horizontal pump ispermitted to travel in both directions (uphole or down-hole) along thehorizontal tubing segment between the horizontal pumps. This conditioncan present as sustained pressure elevation at the discharge end of theadjacent horizontal pumps which condition will cause an escalation inthe required discharge pressure at adjacent pumps and may in somecircumstances entirely prevent the adjacent pumps from discharging intothe common and substantially horizontal tubing string. Therefore, thesolution is to provide directional flow control devices placedimmediately down-hole of each horizontal pump to ensure that thedirection of flows of the pump discharge is directed only from thedistal end of the first fluid flow path towards the proximal end of thesame.

Pump placement along the horizontal wellbore section and particularly inrelation to the fracture intervals and the troughs of the trajectory hasproven to be an important factor in overall system operation and as suchis captured within this improved system application. To that end andfurther a method and system for collecting data for subject wells andpotential analog wells and then assembling the data for presentation ispresented here. Further, the assembled data is used to present anartificial lift system design for the betterment of the well'sproduction and ultimately to access stranded reserves from the deepestportion of the substantially horizontal segment of the subject wellbore.

Interpretation

The description of the present invention has been presented for purposesof illustration and description, but it is not intended to be exhaustiveor limited to the invention in the form disclosed. Many modificationsand variations will be apparent to those of ordinary skill in the artwithout departing from the scope and spirit of the invention.Embodiments were chosen and described in order to best explain theprinciples of the invention and the practical application, and to enableothers of ordinary skill in the art to understand the invention forvarious embodiments with various modifications as are suited to theparticular use contemplated. To the extent that the followingdescription is of a specific embodiment or a particular use of theinvention, it is intended to be illustrative only, and not limiting ofthe claimed invention.

The corresponding structures, materials, acts, and equivalents of allmeans or steps plus function elements in the claims appended to thisspecification are intended to include any structure, material, or actfor performing the function in combination with other claimed elementsas specifically claimed.

References in the specification to “one embodiment”, “an embodiment”,etc., indicate that the embodiment described may include a particularaspect, feature, structure, or characteristic, but not every embodimentnecessarily includes that aspect, feature, structure, or characteristic.Moreover, such phrases may, but do not necessarily, refer to the sameembodiment referred to in other portions of the specification. Further,when a particular aspect, feature, structure, or characteristic isdescribed in connection with an embodiment, it is within the knowledgeof one skilled in the art to combine, affect or connect such aspect,feature, structure, or characteristic with other embodiments, whether ornot such connection or combination is explicitly described. In otherwords, any element or feature may be combined with any other element orfeature in different embodiments, unless there is an obvious or inherentincompatibility between the two, or it is specifically excluded.

It is further noted that the claims may be drafted to exclude anyoptional element. As such, this statement is intended to serve asantecedent basis for the use of exclusive terminology, such as “solely,”“only,” and the like, in connection with the recitation of claimelements or use of a “negative” limitation. The terms “preferably,”“preferred,” “prefer,” “optionally,” “may,” and similar terms are usedto indicate that an item, condition or step being referred to is anoptional (not required) feature of the invention.

The singular forms “a,” “an,” and “the” include the plural referenceunless the context clearly dictates otherwise. The term “and/or” meansany one of the items, any combination of the items, or all of the itemswith which this term is associated.

As will be understood by one skilled in the art, for any and allpurposes, particularly in terms of providing a written description, allranges recited herein also encompass any and all possible sub-ranges andcombinations of sub-ranges thereof, as well as the individual valuesmaking up the range, particularly integer values. A recited range (e.g.,weight percents or carbon groups) includes each specific value, integer,decimal, or identity within the range. Any listed range can be easilyrecognized as sufficiently describing and enabling the same range beingbroken down into at least equal halves, thirds, quarters, fifths, ortenths. As a non-limiting example, any range discussed herein can bereadily broken down into a lower third, middle third and upper third,etc.

As will also be understood by one skilled in the art, all rangesdescribed herein, and all language such as “up to”, “at least”, “greaterthan”, “less than”, “more than”, “or more”, and the like, include thenumber(s) recited and such terms refer to ranges that can besubsequently broken down into sub-ranges as discussed above.

1. A pump system for producing fluids from a reservoir using a wellborehaving a vertical section with a casing defining a wellbore annulus, ahorizontal section in fluid communication with the wellbore annulus, anda production tubing having a vertical section, a horizontal section anda toe end, the production tubing defining a continuous flow path fromthe toe end to the vertical section, the system comprising a pluralityof horizontal pump assemblies operating in parallel in the productiontubing horizontal section, each assembly comprising: (a) a pump havingan intake exposed to the reservoir and an outlet in the continuous flowpath; and (b) a fluidseeker defining an inner conduit forming thecontinuous flow path and defining an inlet chamber, the fluidseekercomprising an axially rotatable inlet extension disposed in the inletchamber and having a weighted keel defining inlet ports which are influid communication with the inlet chamber and a fluid inlet for thepump.
 2. The system of claim 1 further comprising at least onedirectional flow control device disposed in the continuous flow path,between adjacent pump assemblies.
 3. The system of claim 1 wherein eachpump assembly comprises a one-way valve on one or both of the pumpintake and pump outlet.
 4. The system of claim 2 further comprising atubing drain adjacent and downstream of said directional flow controlvalve.
 5. The system of claim 1 wherein each pump assembly comprises aclutch assembly which permits rotatable alignment of the capillary linesor electrical lines within the pump assembly with the lines affixed tothe adjacent tubulars at the distal and proximal ends of each said pumpassembly during installation and deployment of the same.
 6. The systemof claim 1 wherein each pump assembly comprises a reciprocating rodpump, a diaphragm pump, an electric submersible pump, a hydraulicsubmersible pump, a jet pump, a pneumatic drive pump, a gas lift pump, agear pump, a progressive cavity pump, a vane pump or combinationsthereof.
 7. The system of claim 1 wherein each pump comprises anelongate diaphragm pump defining a central fluid passage forming thecontinuous flow path, wherein the pump intake receives produced fluidfrom the fluidseeker and the pump outlet combines with the continuousflow path at an uphole end of the pump.
 8. The system of claim 1 whereinat least one pump assembly is positioned in an elevational trap in thehorizontal section.
 9. The system of claim 1, further comprising acontrol system connected to each horizontal pump assembly, which isoperative to vary a pump rate of each horizontal pump independently. 10.The system of claim 9 further comprising at least one sensorfunctionally associated with each of the horizontal pumps, for measuringand transmitting flow, pressure and/or temperature data to the controlsystem.
 11. The system of claim 10 further comprising a plurality ofsensors functionally associated with each of the horizontal pumps, formeasuring and transmitting flow, pressure and/or temperature data to thecontrol system.
 12. The system of claim 1 further comprising a fluidflow management and separation system, comprising a wavebreaker, aninline fluidseeker, and a separator, wherein the continuous flow pathpasses through the system and the inline fluidseeker provides a bypasspassage leading to the separator and an inlet which combines with thecontinuous flow passage.
 13. The system of claim 1 further comprising afloat and level switch associated with each inlet extension, for sensingliquid level in the fluidseeker and controlling operation of the pump.14. The system of claim 1 further comprising a vertical lift pumpdisposed in a transition section of the wellbore, or a heel segment ofthe horizontal section.
 15. The system of claim 14 wherein the verticallift pump is a high-angle reciprocating rod pump.
 16. A method ofproducing fluids from a reservoir using a wellbore having a verticalsection with a casing defining a wellbore annulus and a horizontalsection in fluid communication with the wellbore annulus, the methodcomprising the steps of: (a) installing a production tubing defining acontinuous flow path from a toe end of the horizontal section to thevertical section, wherein the production tubing is closed to thereservoir except through a plurality of horizontal pumps installed inthe production tubing; (b) operating each horizontal pump, wherein eachpump has a fluidseeker inlet disposed in a lower part of the horizontalwellbore, and each pump discharges into the continuous flow pathindependent of other pumps; (c) wherein each pump has an associateddirectional flow control device to organize the commingled pumpdischarge flow in the continuous flow path.
 17. The method of claim 16wherein each horizontal pump is operable to pump fluids from eachindependent, substantially horizontal wellbore segment towards theproximal end of the central flow path, commingling with the fluids froma substantially depleted reservoir segment and entering a primaryvertical lift system intake.
 18. The method of claim 17 furthercomprising the steps of: (a) separating liquids and gases by means of ahorizontal separator concentrically disposed and surrounding thecontinuous flow path at a distal end of a transitional build section;(b) pumping liquids towards surface from the separator with the verticallift system; (c) allowing gases to rise through the well annulus towardssurface; (d) separating liquids and gases by means of a horizontal pumpseparator adjacent to and upstream of each horizontal pump andconcentrically disposed and surrounding the continuous fluid path in anyhorizontal wellbore segment; (e) pumping separated wellbore liquids withthe at least one horizontal pump into the continuous flow path andtowards the transitional build section.
 19. The method of claim 16wherein a control system is connected to each horizontal pump, whichcontrol system is operative to vary a pump rate of each horizontal pumpindependently.
 20. The method of claim 19 wherein the control systemreceives data from a plurality of downhole sensors, and processes thedata to vary operation of each pump independently.
 21. The method ofclaim 16 wherein at least one horizontal pump is placed in anelevational trap or area of inefficient production in the horizontalsection.
 22. The method of claim 21 wherein the location of the trap orinefficient production is determined by the collection and processing ofdata collected by a plurality of sensors deployed in the horizontalsection, prior to installation of the production tubing and horizontalpumps.
 23. A diaphragm pump assembly for use in removing liquid from asubterranean wellbore, comprising: (a) at least one pumping unit havinga rigid housing, a central internal mandrel and a flexible diaphragmdisposed within the housing, wherein the diaphragm defines a sealedactivation chamber with the rigid housing and an internal productionchamber, and wherein the production chamber comprises a fluid inlet anda fluid outlet; (b) an activation conduit in fluid communication withthe activation chamber; (c) an exhaust conduit in fluid communicationwith the activation chamber; (d) a production conduit in fluidcommunication with the production chamber fluid outlet; (e) at least onecheck valve associated with either or both of the production chamberfluid inlet or fluid outlet; and (f) a fluidseeker associated with thefluid inlet, the fluidseeker defining an inlet chamber, and comprisingan axially rotatable inlet extension disposed in the inlet chamber andhaving a weighted keel defining inlet ports which are in fluidcommunication with the inlet chamber and a fluid inlet for the pump. 24.(canceled)